Our nation's pipeline system is unsafe, and it can be much safer. Pipelines hurt and kill people, damage property, and foul our environment in far too many preventable accidents. Yet the highly-profitable pipeline industry does little to prevent accidents, knowing that there are few meaningful consequences when accidents happen, and federal regulators have historically done little to impose any effective consequences.

Consider these facts: There have been 19,214 oil pipeline accidents in the United States since 1991, according to the Coast Guard's National Response Center. In that same period, oil pipelines have spilled nine times as much oil in the United States as tankers and barges, according to consultant Dagmar Etkin, former research editor of the Oil Spill Intelligence Report. Since 1986, natural gas pipeline accidents nationwide have killed 346 people and injured 1,501.

Inaccurate Pipeline Accident Data

Lack of Other Pipeline Data

Causes of Oil Pipeline Accidents

Aging, Deteriorating Pipeline System

Unsafe Design and Construction Practices

Unsafe Siting and Right-of-Way Protection Practices

Neglect of Defect and Leak Detection

Understaffed, Underskilled Pipeline Operations

Neglect of State and Local Land-Use Responsibilities

TIMELINE OF PIPELINE ACCIDENTS, INJURIES AND DEATHS 1989-2001

Inaccurate Pipeline Accident Data

There were 19,214 oil pipeline accidents in the United States from 1991 to 2001. There were 2,051 oil pipeline accidents in the United States from 1991 to 2001. The former statistics comes from the Coast Guard's National Response Center, the latter from the Office of Pipeline Safety (OPS). Which number is correct? The answer is NOBODY KNOWS.

The pitiful fact is that no accurate data on oil, or even natural gas, pipeline accidents exist. Most at fault is the OPS, which has near-exclusive authority to regulate pipelines.

Consider this:

• Until 2002, OPS required reports on oil pipeline accidents only if they exceeded 50 barrels (2,100 gallons) lost. Beginning in 2002, OPS requires reports on spills of five gallons or more, but only in limited cases.

• OPS still requires NO REPORTS on accidents on gathering, rural and low-pressure pipelines, which make up almost a third of all oil pipelines and are notorious for leaking and spilling.

• Accident data are self-reported and not verified, so that pipeline companies can falsify data sent to OPS, for example, by UNDERESTIMATING OIL LOST or the amount of property damage, or by providing misleading information about the causes or other details.

• Simply not reporting even reportable spills is a widespread problem, as documented by the General Accounting Office in 1987, which stated that it was UNABLE TO DETERMINE the full extent of the problem.

The Coast Guard data are even less reliable, given that they generally include only the initial report of oil pipeline accidents in or near U.S. waters, record even lower volumes of oil lost, and lack follow-up information after the initial report of an accident.

Many state and local records are more accurate and record far more accidents. For example, state agencies in Florida require reports of pipeline spills of a gallon or more. These reports show that Sunniland Pipeline, a crude oil pipeline that crosses the Everglades, had 54 accidents from 1974 to 1996, with losses totaling 160,000 gallons. For the same pipeline, the OPS has only one spill on record. However, state data are often inaccessible, lack uniformity, and are useful only in limited cases.

Ironically, pipeline companies keep thorough records of their accidents. In fact, the California State Fire Marshal Hazardous Liquid Pipeline Risk Assessment report (1993) reported that, "with one exception, all operators [in California] had kept records on nearly every leak which had occurred on their lines, regardless of size or severity," adding that "this practice had become necessary to enable them to successfully defend claims against them for generating contaminated soil near their pipelines."

As a result, policymakers don't even know how many pipeline accidents happen, much less where, their causes, their consequences, or how well or even if the damage was repaired. This means that safety agencies have NO DATA TO DETERMINE THE TRUE RISK FACTORS of pipeline accidents, what can be done to prevent them or mitigate their impacts, which companies have better safety records than others, or even if pipelines are getting safer or not. For example, according to OPS data:

• Fully 30 percent of all oil pipeline accidents reported to the OPS from 1987 to 2001 were caused by "Other," which provides no clue for assessing risks. However, a New Jersey Institute of Technology (NJIT) report in 1996 found that accidents attributed to "other" were often related to pipe system component failures, such as O-rings, nipples and gaskets.

• Because they are self-reported and not verified, oil pipeline company reports exaggerate "outside force" as a cause, according to American Society of Mechanical Engineers (ASME) data on pipeline accidents.

Even the industry has recognized the need for more complete and accurate accident data. The American Petroleum Institute recently began the Pipeline Performance Tracking System (PPTS), which has collected confidential data on spills of five gallons or more, beginning in 1999, from 35 of the largest oil pipeline operators. "In 1998, the leadership of the oil pipeline industry concluded that lack of data had prevented operators, collectively, from learning all they could or need to learn from pipeline accidents," stated authors representing the API in the Oil & Gas Journal of November 11, 2002.

• However, these data cover too few years (nothing before 1999) for meaningful analysis and, because of their confidentiality, are not available to regulators or the public and therefore not useful for policy making.

This deplorable lack of accident data means that the OPS drive for risk-based regulation, if achieved, would be based on no verifiable understanding of the real risks. It means that cost-benefit analyses, required by the Pipeline Safety Act amendments of 1996 in considering new regulations, would be based on gross underestimates of property damage caused by pipeline accidents (thus the economic benefits of reducing their number and severity). And it means free rein for the pipeline industry and individual companies to continue making false claims about their safety and environmental records.

Lack of Other Pipeline Data

Three other very important areas of information about pipelines are lacking — the age and characteristics of regulated pipelines, maps of where they are, and anything about exempt pipelines — seemingly essential if the OPS is to regulate pipelines effectively. As our system of underground pipelines continues to age in place — and gathering and low-pressure lines leak and spill — this information is crucial to understanding the growing risks of accidents and the necessity for a systematic program to rehabilitate these pipelines.

• NO PIPELINE SYSTEM INVENTORY. Despite the need for an up-to-date inventory of pipelines, the OPS has no such information. It does not systematically collect and analyze information about the age of individual pipelines or segments, their pipe materials, pipe thickness and coatings, cathodic protection, cover depth, density of surrounding urban development and many other important risk factors.

• CONTRAST WITH CALIFORNIA. However, the California State Fire Marshal Hazardous Liquid Pipeline Risk Assessment report in 1993 compiled a thorough inventory of the 7,800 miles of oil pipelines operating in that state during the 1980s. The information included over 30 characteristics, used as risk factors to analyze where regulatory efforts could yield the greatest benefit. For example, it found that 20 percent of oil pipeline mileage in California was built before 1940, with a rate of accidents 20 times higher than pipelines built in the 1980s.

• NO MAPS. That OPS has no comprehensive file of maps of either the natural gas or oil pipelines it regulates is especially baffling. Although it requires pipeline companies to keep such maps, OPS does not have a comprehensive compilation for regulatory purposes. In 1990, OPS even rejected a suggestion that it require companies to give them such maps, agreeing with the industry argument that this would impose on them an unnecessary expense. Later, OPS began a voluntary program, the National Pipeline Mapping System, which has the goal of 70 percent compliance only. As a result, OPS regulates an industry with no knowledge of where its facilities are. Exasperated by this inaction, Congress decided to require pipeline operators to submit electronic maps to OPS within six months of enactment of the Pipeline Safety Improvement Act of 2002, signed into law on December 17, 2002.

• NO DATA ON LEAKING EXEMPT PIPELINES. In addition to about 155,000 miles of regulated oil pipelines, about 60,000 miles of gathering or low-pressure pipelines exist in the United States — but are exempt from regulations because OPS considers them not a safety or environmental problem. Although state pipeline accident data show that such pipelines cause serious environmental damage, OPS collects no data on them.

Causes of Oil Pipeline Accidents

Despite these inaccuracies, OPS pipeline accident data about causes of accidents at least contradict the pipeline industry's claim that third-party damage is the leading cause of accidents. The industry uses this claim to imply that operators have no control over such accidents, and that the fault lies elsewhere.

However, OPS accident data show that third-party damage causes fewer than 20 to 25 percent of all petroleum pipeline accidents, that companies could prevent many of these, and that the vast majority are caused by CORROSION, IMPROPER OPERATION, AND OTHER FACTORS UNDER THEIR CONTROL.

• PIPELINE COMPANIES BLAME OTHERS. Pipeline companies routinely exaggerate the role of outside force and third-party damage. They tend to blame someone else, buttressing their emphasis to promote new laws and public relations campaigns to promote "one-call" systems, an 800-telephone number for excavators to call before digging, and thereby avoid damaging a buried line.

• COMPANY MISTAKES ARE GREATEST CAUSE. At least three out of four pipeline accidents are caused by the companies themselves and could have been prevented by simple precautions. OPS oil pipeline accident reports show this clearly: OPS DATABASE CAUSES OF OIL PIPELINE ACCIDENTS)
  
  
• STUDIES SUGGEST THAT 3RD PARTY DAMAGE IS NOT A MAJOR CAUSE
• A Battelle Memorial Laboratory study showed an even smaller role for outside force damage, although the data were for one year only. Adjusting OPS data by mile-years, Battelle found that outside damage accounted for only 18 percent of the accidents per mile-year, while operational error accounted for nearly half. The 1992 data show: BATTELLE STUDY CAUSES OF OIL PIPELINE ACCIDENTS

 

• The Hazardous Liquid Pipeline Risk Assessment report by the California State Fire Marshal (1993) surveyed pipelines incidents in that state from 1981 to 1990 and confirmed the relatively secondary role of third-party damage. It found that nearly 60 percent were caused by external corrosion, while third-party damage accounted for only about 20 percent. Shown here: CALIFORNIA STATE FIRE MARSHAL CAUSES OF OIL PIPELINE ACCIDENTS IN CALIFORNIA

 

• NO PIPELINE MARKERS A KEY FACTOR. In 62 percent of the accidents reportedly due to outside damage, the location of the pipeline had not been marked by the pipeline company, according to a 1996 report by the National Transportation Safety Board (NTSB).
  
  
  • Outside damage caused only 28 percent of the accidents reported to OPS from 1986 to 1994, according to the report, however, sharply criticized OPS data, stating that,

• REAL CAUSES DOWNPLAYED. These four studies suggest that improved maintenance, materials, inspection, operator error reduction, leak detection and prevention, and corrosion control are far more important for reducing pipeline accidents - yet receive relatively little attention from industry or government regulators.

• "OUTSIDE DAMAGE" MISUNDERSTOOD. Reviewers of pipeline accident data should note that "outside damage" is not the same as "third-party damage." Outside damage is simply damage done to the outside of a pipeline; the company's employees or contractors often cause such damage. So too do employees or contractors of other linear facilities (such as railroads or natural gas pipelines) sharing a right-of-way with a petroleum pipeline. The careless backhoe operator or other person unrelated to pipeline or other linear facilities are thus a lesser cause of outside damage, or even third-party damage, than generally acknowledged. Even who the "third parties" are is misunderstood, according to API analysis of its PPTS data. From 1999 to 2001, farming activities were the leading cause of third-party damage to pipelines, followed by other underground facilities operators (including other pipeline operators) ñ not conventional excavators that are the focus of damage prevention programs.

• FAILURE TO DETECT DEFECTS A MAJOR FACTOR. Further, many "outside damage" accidents happened because pipeline companies either failed to detect the dents or cracks that later develop into ruptures — or did detect the dents or cracks but did not repair them, even after years have passed since detecting them.

• OUTSIDE DAMAGE LEADING CAUSE FOR NATURAL GAS PIPELINES. In contrast, outside damage is the leading cause of natural gas pipeline accidents. It accounts for half of all such accidents reported to OPS in the years 1995 to 2001, followed by "other" and internal and external corrosion. See table: OPS Database Causes of NATURAL GAS Pipeline Accidents

Aging, Deteriorating Pipeline System

"The vast bulk of the pipeline system, for example, was constructed decades ago. Large segments of it are aging," Transportation Secretary Federico Pena stated at the National Pipeline Safety Summit in 1994, convened after the Edison NJ natural gas explosion.

• Half of all oil and natural gas pipeline miles built after 1947 were constructed before 1969, according to totals compiled by the trade publication, Pipe Line and Gas Industry. Along with those built in 1947 and earlier (and still in service), these pipelines are often POORLY MAINTAINED AND MONITORED, and the chances that they will spill or explode increase significantly as they age.

• The oil pipeline system is even older. Only one-third of oil pipelines in use today were built after 1969, according to the APIís 2001 report, "Oil Pipeline Characteristics and Risk Factors: Illustrations from the Decade of Construction."

• As many miles of oil pipelines in use today were built in the 1930s as in the 1990s, the report showed.

• AGING OFFSHORE PIPELINES. The National Research Council voiced a similar concern that much of the nation's 20,000-mile offshore pipelines system "has remained in use beyond its originally intended use," in its 1994 report, Improving the Safety of Marine Pipelines. It stated,

• OLDER PIPELINES MEAN MORE ACCIDENTS. Industry officials contend that well-maintained pipelines can theoretically last for 100 years or more, but the reality is that the older a pipeline is, the more likely an accident becomes. Oil pipelines built before 1940 in California had an accident rate 20 times higher than one built in the 1980s, primarily because of corrosion, according to the California State Fire Marshal Hazardous Liquid Pipeline Risk Assessment report (1993). Those built in the 1940s had an accident rate eight times higher.

• NO SYSTEM IN PLACE FOR REPLACING OLD PIPELINES. Despite the certainty that pipelines have more accidents as they age, there is no systematic federal program to identify and replace them. In fact, there is no federal requirement that a pipeline ever has to be replaced.

Unsafe Design and Construction Practices

New construction adds only about one percent a year to the nation's natural gas and oil pipeline mileage, so the inadequacies of the installed system will remain dangerous for decades to come. Even new pipelines continue to be built with materials and construction techniques that will mean hazards in later years.

• CRACKING, CORRODED AND DENTED PIPELINES ALLOWED. OPS regulations today allow companies to build low-pressure lines with dented, cracked, corroded pipe if they want to. The rolled and electric resistance welded (ERW) steel pipe commonly installed in the 1950s and 1960s can rupture along its lengthwise seam, under certain conditions. Other problems that have plagued the pipeline industry include "railroad fatigue," tiny cracks in pipe caused by improper stacking on rail cars used for transporting pipe to the construction site.
  

• PIPELINE THICKNESS. Despite the fact that thicker oil pipeline walls can reduce the chances that outside damage, corrosion or other problems will result in a leak or rupture, OPS standards permit the thinnest wall thickness of any major national pipeline codes. In fact, federal standards require thicker steel pipe for high-pressure water pipelines (a minimum 0.485 inches) than for high-pressure oil pipelines (0.337 inches). This can be a special problem with pipelines laid in rural areas that later become densely developed as urban sprawl continues; there is no requirement that a company must then replace the original pipelines with thicker wall pipe to provide better protection from third-party damage. High-pressure natural gas pipelines in populated areas must be a minimum of 0.606 inches thick.

• PIPE COATINGS. Protective pipe coatings are commonly used to protect bare steel from outside corrosion. OPS standards require coatings on new pipes but do not specify what types. Such coatings are usually asphalt or coal tar, applied at the mill or during construction of the line. However, even when coatings are applied, incorrect application, inferior coating materials, or damage during pipeline construction or by a third-party can breach the coating and defeat its effectiveness.

• JOINT WELDS. Because improper construction of pipelines can create long-undetected defects, rigorous adherence to correct standards and close supervision during construction are vital — the more so because independent contractors typically do every phase of the construction. Precise welding of pipe lengths together is crucial, because welds can be especially vulnerable to corrosion or failure. However, OPS standards require an X-ray test of only one out of every 10 welds during construction. Afterwards, these defects can be impossible to detect.
  

• PROPER LAYING OF PIPELINES. Proper laying of pipe in the ground is also crucial, with the pipe required to be installed on soft soil or other padding and covered by similar material. Pipe resting on large rocks or other sharp objects can become dented and gouged as the pipe vibrates during normal operations, and such faulty construction is not uncommon.

• Following the massive rupture in 1993 of Colonial Pipelineís 36-inch line near Herndon VA, investigators found the pipe resting on large, sharp rocks that had damaged the pipe. Colonial chief executive Donald Brinkley told a Congressional hearing two months later that "obviously you have 5,390 miles of pipe, you are going to occasionally find it sitting on a rock." Because of understaffing, OPS does not have field inspectors present during all phases of new pipeline construction.

• SHUT-OFF VALVES. Shutoff and block valves are important to isolate ruptures or to conduct routine maintenance, and are especially important for limiting the size of spills and their impacts on public safety and the environment. Automatic and remote-controlled valves are especially preferable to manual valves, which can be inaccessible during an emergency — yet manual valves predominate. A study for the U.S. Department of Energy in 1989 found that only 12.4 percent of all main-line block values in interstate pipelines were remote-controlled. Closer spacing of block valves is also a key to limiting the volumes of natural gas or oil released by an accident.

• About half of the volume lost in all oil pipeline accidents were from large spills that could have been reduced by more closely spaced valves, according to a study by the Volpe National Transportation System Center in 1995. At the location of the 1993 Colonial Pipeline 408,000 gallon fuel oil spill in Herndon VA, valves were 45 miles from each other.

   

• Also, valves are often poorly maintained and simply may not work during emergencies. OPS requires only minimal use of any sort of valves and has rejected repeated recommendations by the NTSB for stricter standards.

• ANTI-CORROSION PROTECTION. OPS requires cathodic protection against corrosion on all interstate and new oil and natural gas pipelines, but some of the system in use today has no such protection. Cathodic protection involves various means to send electric currents through the steel pipelines to counter external corrosion caused by stray leakage of currents from adjacent pipes, metal structures, or electrical installations. Even when used, according to Battelle Memorial Laboratory, "corrosion still occurs on some [cathodically protected] lines." The California State Fire Marshal Hazardous Liquid Pipeline Risk Assessment report (1993) found that lines with cathodic protection still had over four corrosion-caused leaks each year per 1,000 miles of pipeline.

Unsafe Siting and Right-of-way Protection Practices

The widespread use of one-call systems, which require excavators to contact pipeline companies before beginning to work, has significantly decreased the number of accidents caused by third-party damage. As the NTSB reported in 1998, excavation damage caused an estimated 50 to 60 percent of pipeline accidents in the 1970s, but today causes only about 25 percent of them.

However, serious problems remain in the legacy of unsafe pipeline siting decisions made decades ago, siting of new pipelines today, and in the failure of pipeline companies to both patrol their rights-of-way effectively for hazardous activities and follow up when such activities are detected. For example:

• In building its mainline network supplying fuels to the Eastern U.S., Colonial Pipeline installed a 40 inch pipe in a landfill in the Morgan Falls community northeast of Atlanta, which leaked over 36,000 gallons of gasoline in 1998. The leak was discovered by people using the recreation park built on the now-closed landfill. Before responders contained the leak, gasoline nearly reached a creek flowing into the Chattahoochee, the main source of drinking water for metropolitan Atlanta.

Over half the length of the proposed 700-mile Longhorn Pipeline from Houston to El Paso, TX -would use an inactive crude oil pipeline built in 1950 that traverses numerous now-densely urbanized areas from Houston to Austin. Only determined resistance by several local governments forced Longhorn to submit to an EPA environmental assessment, the results of which are in dispute as the deadlock over completing the project continues. See MAP

• Texas Eastern sited its 36-inch diameter natural gas pipeline in 1960 through an asphalt plant property in Edison NJ where the pipeline exploded in flames in 1994, causing extensive property damage, 70 injuries and one death. The NTSB investigation included numerous aerial photographs of the site since then that clearly showed various excavation and dumping activities that violated the pipeline easement agreement. "Asphalt company crews dredged the sediment pond, filled in the ponds, built an earthen berm, installed underground piping, and stockpiled plant process materials" over the years, the report noted. However, Texas Eastern patrollers FAILED TO REPORT these activities OR ENFORCE THE AGREEMENT or confer with the owners about taking actions which could have prevented the accident.

Neglect of Defect and Leak Detection

• PLENTY OF LEAKS AND SPILLS TO DETECT. In just one of several such analyses, the California State Fire Marshal's Hazardous Liquid Pipeline Risk Assessment report (1993) found that there were 7.1 accidents per year per thousand miles of oil pipeline in California during the 1980s. This suggests that more than three such leaks and spills happen per day nationwide on average. The U.S. Coast Guard National Response Center reporting system (separate from OPS's system) records nearly twice that many leaks and spills from oil pipelines.

• OPS NEGLECTS LEAK DETECTION. Yet federal regulators leave leak detection standards to the discretion of pipeline companies. There are no blanket requirements for inspections by "smart pigs," computerized line monitors, hydrostatic testing, or other such measures. The only explicit LEAK DETECTION requirement is for visual surveillance of rights-of-way at least 26 times a year. Because of federal preemption, state and local agencies have no ability to require interstate (or most intrastate) oil and natural gas pipelines to use any leak detection measures not required by federal regulations.
  
  
• Even what the industry calls "state-of-the-art" measures are severely limited and fail to detect defects and leaks that can create serious pollution. One conclusion from the APIís study of PPTS data in 2002 was that, "basically, people find leaks ñ local operations people . . . or third parties." It found that pressure and flow measuring devices "available to control room personnel on their consoles, for instance, are not going to show smaller leaks at all, and changes will not be apparent instantaneously even for large leaks." The much-touted supervisory control and data acquisition system (SCADA) is good for "finding large leaks, not generally small ones," the API study noted.
  
  
• OPS INSPECTIONS FALL SHORT. Because of understaffing, OPS field inspectors do not physically inspect for defects or leaks after new pipelines begin operating; they rarely even inspect when they are under construction. Neither does OPS investigate nine out of 10 reported accidents. Essentially, the responsibility for leak prevention and detection falls on the pipeline companies.

• The only explicit federal requirement for regular inspection and leak detection is that companies visually inspect surface conditions on or near pipeline rights-of-way at least 26 times per year. That method presumes that someone flying overhead in an airplane or helicopter every two weeks will see brown vegetation or other signs of a leak and thus prevent damage to our environment. This method is limited if the vegetation is already brown, or severe weather limits flights and visibility, or the leak started in between flights. This method accounts for virtually none of the leaks reported to OPS. A 1989 U.S. Department of Energy study stated, "This method is often not sensitive to small leaks, and the response time is limited by the inspection frequency."

• Slow, steady leaks create special problems because they are so difficult to detect and locate, and can cause severe soil and groundwater contamination if they persist for long periods. As a Williams Pipeline Company executive told the 1995 API Annual Pipeline Conference,

• Locating a "seeper" [a very slow leak] in a 30 mile test section has to be one of the pipelinerís greatest challenges. We have located "seepers" with a pressure drop at less than 1 psig in 15 minutes in a 30 mile test section. The only problem is it usually takes five to seven days to locate a leak of this magnitude in a test section this long.

• OPS HAS LITTLE RECORD OF ENVIRONMENTAL DAMAGE. The U.S. Department of Energy study in 1989 made the important observation that "little information is available on the extent of pipeline leaks of environmental concern, as opposed to those largely of concern because of safety." This underscores the fact that the OPS program and its standards had addressed safety only — preventing deaths, injuries and property damage — not preventing environmental damage, despite Pipeline Safety Act amendments in 1992 which required OPS to adopt environmental protection regulations.

• ENVIRONMENTAL REGULATIONS ARE NARROW, INADEQUATE. Those regulations went into effect in 2001, when it adopted "integrity management" regulations for oil pipelines in "areas unusually sensitive to environmental damage" and other "high consequence areas." While a welcome first step, the regulations severely limit environmental (and safety) protections by so narrowly defining the pipelines which merit adequate safety standards. In fact, these are such a departure from most other federal and state environmental laws that they continue to frustrate pipeline safety reformers.

• INDUSTRY LEAK DETECTION TECHNIQUES IN QUESTION. The U.S. Department of Energy study in 1989 cited above also reviewed the effectiveness of the eight major techniques for leak detection and noted, "It is reasonable to expect that small leaks occur but that not all leaks could be detected using current approaches."

• COMPUTERIZED PIPELINE MONITORS. For example, in statements to the public, the industry cites its use of computerized line monitors or SCADA systems, as a way to detect leaks instantly. These monitor the flow rate, volume and pressure of fuel, adjusting for such myriad factors as temperatures, pipe diameter, fluid viscosity, line hydraulics and other factors that affect measurements. Sudden changes and some gradual changes can signal pipeline controllers of a problem.

  However, among themselves, pipeline industry experts understand that such systems are far from foolproof. For example, they cannot detect small leaks, generally those that lose less than one percent of volume, according to several studies, including a 1993 study by the API, "Pipeline Variable Uncertainties And Their Effects on Leak Detectability."

• - In fact, the California State Fire Marshal Hazardous Liquid Pipeline Risk Assessment report (1993) found that, while lines with SCADA systems had about 40 percent fewer spills, they also had larger spills and do not "reduce leak incident rates."
• - A 1995 study for OPS by the Volpe National Transportation Systems Center reported widespread concerns in the industry about SCADA false alarms, poor input information, uneven flow conditions, and program bugs and other startup complications. It noted that small leaks are "below the limits" of SCADA systems in current use and stated, "These small leaks can stay small and go unnoticed for weeks."

 

• By 2000, SCADA systems had not improved much, according to a panel of industry experts at an NTSB public hearing that year on pipeline integrity. Ken McCoy of Tracetec Product Group remarked that drops in volume of three to five percent or higher were quickly detectable. Smaller leaks took longer, he said, and "very small leaks may go undetected in their entirety."

 

• At the same hearing, several experts noted that a well-trained control room staff is essential for SCADA systems to work up to their limited potential. Even a big spill can go undetected if the operator is not careful, because it causes a sudden drop of pressure or flow that then stabilizes. "You're looking for that initial shock wave that takes place," said Bob Darwin of the API. "If you miss that, within a matter of minutes, it will factor itself back in to a new steady state on the pipeline, and you miss it." Industry critics have long noted the lack of experienced, skilled control room staffs in recent years.

 

• SMART PIGS USEFULNESS IS LIMITED. The industry also touts its use of smart pigs, instrumented internal inspection devices as reliable ways to detect dents, cracks, and other defects in pipes. In reality, smart pigs have limited usefulness, according to several studies:

• The General Accounting Office polled 15 pipeline companies in a study released in 1993 and found a consensus that pigs could not detect metal loss in welds, cracks that run the length of pipes, seam failure, or the condition of external coatings.

• The Battelle Memorial Laboratory noted similar limitations, in a paper submitted to the 1994 National Pipeline Summit.

• A Conoco, Inc., executive stated at the same National Pipeline Safety Summit that a smart pig "will not detect failures in the weld seam nor in the girth weld, and it will reflect a pop can or welding rod end buried near the pipe just as if it were a defect in the pipe wall."

• In a paper at the 1995 API Annual Pipeline Conference, Keith Grimes of BG Inspection Services Inc., stated that "cracks have proven to be the most difficult type of defect to detect, and there is currently no commercially available in line inspection system with proven crack detection capability."

However, smart pigs can find many defects and could help improve pipeline safety — if pipeline companies used them widely and frequently, WHICH THEY DO NOT. There is no federal requirement that all oil and natural gas pipelines use them. Those that voluntarily use them use them sparingly because of purported costs of $1,000 to $4,000 per mile of pipeline inspected. Many older pipelines simply cannot accommodate these devices because of sharply angled turns, pipe diameter changes, or other constraints.

• HYDROSTATIC TESTING IS USED EVEN LESS. Hydrostatic testing is more useful, but rarely employed on a regular basis because of cost. The API stated in 1987 that the average cost for hydrostatic testing was $5,300 per mile and that "the expected net effect of mandated hydrostatic testing would be virtually no increase in overall safety." Federal regulations require hydrostatic testing of new pipelines when built only, and testing only once of pipelines built before 1985. There is no requirement for regular testing after the initial test, even though the NTSB has advocated such a requirement since 1978.

• MANY USEFUL TECHNIQUES ARE NOT BEING USED AT ALL. Much more important than the methods commonly used by pipelines are those not being used, even though they could significantly decrease leaks and spills. Direct leak detection systems using hydrocarbon sensing cables have been used successfully in numerous locations by Chevron, GATX, and airport authorities in Denver, Japan, and South Korea. Regular hydrostatic pressure tests can spot small defects that smart pigs and SCADA tests miss. Foot or ground vehicle patrols can be much more effective than the most commonly used method, aircraft patrols. More automatic and remote-controlled shutoff valves, improved smart pigs, field recoating of pipes, double-wall pipes, and new land-use regulations can all help reduce spills and damage.

• ONE CANADIAN SYSTEM USES "MAN'S BEST FRIEND." One innovative leak detection system developed by Esso Canada uses an odorant called "Tekscent" for hydrostatic pressure tests of problem pipe with otherwise undetectable leaks. After adding Tekscent to fluid injected in the pipe, handlers then use trained Labrador retrievers to patrol the surface above the tested pipe and sniff for minute traces of the odor that escape from small pipe cracks, some so small that they are invisible to the naked eye. Despite its proven success in Canada, however, the Tekscent system has failed to attract significant interest from U.S. petroleum pipeline companies.
  
  
  
• PIPELINE SAFETY MANAGERS WARY OF NEW MEASURES. Experts have also noted that experienced pipeline safety managers have been disappointed repeatedly after installing new detection measures on their pipeline systems. Peter Black, in "A Review of Pipeline Leak Detection Technology," in Pipeline Systems (1992), stated,

• The reality of todayís industry is that there is a great deal of suspicion of, and lack of faith in, the vendors of integrity monitoring technology in general, and leak detection software and hardware in particular. . . . Installed systems have often been tuned to give the promised sensitivity promised to the customer, at the cost of a false alarm rate that drove operators to disable the system altogether.

• Then there are pipeline operators who use virtually no leak detection systems other than the required visual inspection system. "Computer systems employed in many large pipeline control centers are very sophisticated," remarked OPS engineer Byron Coy at the NTSB public hearing in 2000, "yet there are many small pipelines across the country that are virtually operated by hand."

LINKS

Leak Detection Systems from LandTech.org
Smart Pigs

GRAPHICS

Leak Detection Techniques, Capacity and Response Times
s Guarding Pipelines Against Rust

Understaffed, Underskilled Pipeline Operations: Higher Profits for Pipeline Companies

After the collapse of sky-high world oil prices in 1986, owners of pipeline companies began a decade-long march to reduce costs by downsizing and outsourcing its cadre of employees, many of them in training, safety, and maintenance programs. The companies laid off many of their most experienced technicians and engineers with a long familiarity with a pipeline system's unique conditions. Instead, they expanded the use of contractors, hired entry-level employees, or simply stopped performing certain functions that help make pipelines safer.

As a result, with operating revenues virtually steady through the past two decades, interstate oil pipeline companies have significantly increased their profits. For example, in the highly-profitable years 1982-86 for the U.S. oil industry, oil pipeline companies had an average annual return on revenues, after taxes, of 31.2 percent. In the most recent five years, 1997-2001, the average annual return was 35.3 percent in the last three of those years, it was 38.6 percent! The increase did not come from increased revenues — it came from reducing costs, especially for personnel — and safety has suffered.

THE COLONIAL PIPELINE EXAMPLE. For example, the OPS conducted an in-depth study of one of America's most troubled oil pipeline companies and issued the report of the Colonial Pipeline Task Force in 1996. It provided a rare spotlight on the internal management of an oil pipeline company, whose practices are probably not unique in the industry. Among its findings:

• Colonial carried out a "re-engineering" in 1994 and 1995 that reduced its crucial headquarters engineering services staff by nearly half, from 46 positions to 25. The cutback meant that no longer did a central staff review and monitor planned maintenance of such key equipment as pumps, instrumentation, relief valves — or analyze the large amount of incoming data that could discern trends and trouble spots.

• Although one of every five reported Colonial Pipeline accidents was caused by "operator error," TRAINING WAS A LOW PRIORITY. Colonial employed a training staff of only five for an operations staff of 485 in 1996. New operators received six months of on-the-job training, paired with an experienced operator but, the report noted, "some field personnel dislike the added duty required for training. The effect is that the exchange of information to the new employees is not consistent."

• Colonial had NO FORMAL CONTINUING TRAINING PROGRAM. The report noted that after six months, new employees would not necessarily ever receive any new training. Colonial responded that the initial training qualified new employees to perform all duties. There was no formal training program for the staff of the vital control center, which must decide when to shut down a pipeline in an emergency.

A STATE PIPELINE REGULATOR'S PERSPECTIVE. In the safety area, pipeline company downsizing and other measures "has cut through the fat and muscle is grinding into the bone," longtime state pipeline regulator Don Stursma stated in 1995.

• Engineering and safety director of the Iowa pipeline safety program, Stursma added, "We see fewer field offices and fewer persons, often relatively inexperienced, in those offices. We wonder if many companies have enough persons left in decision-making roles with the experience and knowledge of field conditions necessary to make informed risk management decisions."

• "Morale is bad out there," he stated. "It is they who have given us the impression of management does not care about safety, service, or employees; only short term cost reductions and playing with the latest fashionable management theories. We have little trouble envisioning directives from industry managers . . . not wanting to hear staff protests that safety would be compromised."

• Stursma concluded that "much knowledge and experience has been lost. Industry today seems increasingly dominated by accountants, lawyers, and MBAs with no technical, safety, or operations background. . . . [We do] not want to see the pipeline industry become like the railroad industry a few years back; squeezed for profits while its infrastructure deteriorated."

Neglect of State and Local Land-Use Responsibilities

State and local government land-use regulations of and near oil pipeline rights-of-way are necessary because the federal Pipeline Safety Act denies OPS the authority to select the route of new oil pipelines or otherwise regulate land use. (Siting of new interstate natural gas pipelines is a federal responsibility.)

The only OPS regulation that mentions siting considerations applies only to new oil pipelines and states, in its entirety:

In fact, OPS officials have publicly stated that land-use regulations concerning oil pipelines are a state and local responsibility.

Further, THERE IS NO FEDERAL REQUIREMENT THAT A STATE OR LOCAL GOVERNMENT APPROVE THE ROUTING PLANS FOR A PETROLEUM PIPELINE, or if it is consistent or not with land-use laws. In fact, governments in other states have denied pipeline companies such rezonings, and been upheld in federal court.

Given that the vast majority of oil and natural gas pipelines are already in the ground, it is imperative that STATE AND LOCAL GOVERNMENTS SHOULD ADOPT NEW LAND-USE MEASURES to prevent encroachment and damage of pipelines.

• In its 1988 study, Pipelines and Public Safety, the National Research Council proposed that state and local governments adopt land-use regulations that prevent encroachment by residential, commercial, and other development, and building codes that can reduce the potential for third-party damage that contribute to pipelines accidents. These include setback requirements, requiring low-density development near pipelines, minimizing disturbance on pipeline easements, and required review of a developer's building plans by pipeline companies.

• The 1996 amendments to the Pipeline Safety Act, in fact, directed the OPS to disseminate and encourage adoption of the NRC recommendations, although the OPS failed to comply, and virtually no state or local government has adopted the NRC recommendations or even seriously considered them.

However, prompted by serious accidents in their communities, some local governments have adopted appropriate land-use regulations to protect pipelines from third-parties. For example:

• In the wake of the fatal natural gas pipeline explosion in 1994 in its township, Edison, NJ, enacted a setback ordinance that forbids the construction of buildings "or land disturbance" within 75 feet of a natural gas or petroleum pipeline and the construction of buildings or structures containing corrosive, toxic, or combustible materials within 125 feet.

• Concerned about contamination from several serious pipeline leaks, Fulton County GA in 1999 adopted setbacks of 40 feet from a pipeline easement for any structure or land disturbance, except what is necessary to provide access to a property. It adopted a 125-foot setback for any structure manufacturing, processing, or storing toxic, combustible or similar materials

• Fairfax County, VA, adopted similar land-use measures in 1995, following a 408,000-gallon fuel oil spill there by Colonial Pipeline in 1993. It decided against setback requirements, fearing "takings" claims by property owners.

• Several local governments in Washington State have adopted land-use restrictions in the aftermath of the Olympic Pipeline explosion in 1999. For example, King County since 2000 has required a 100-foot setback for any building where people live. The City of Redmond in December 2002 adopted a setback of at least 25 feet for most construction, and a 500-foot setback for schools, hospitals, nursing homes, and similar facilities. It also requires pipeline comp0anies to take part in planning and monitoring of construction projects.

One very good reason for state and local governments to adopt such land-use regulations is because pipeline industry executives often complain, when convenient for their immediate purposes, about the lack of local government controls on development near rights-of-way.

• For example, in a Congressional testimony in 1993, Colonial Pipeline president Donald Brinkley complained that local governments failed to prevent encroachment and construction activity that cause third-party damage to pipelines. He suggested numerous building-code and zoning changes.